The human race hit a huge milestone in June 2018–for the first time ever, we used 100 million barrels a day of oil. 

Demand is soaring because the world is growing more prosperous, especially in Asia.  And while there is still a lot of work to do, global prosperity has never flowed so freely to the world’s poor.

This is an empowering statistic.  It should also help buoy oil prices, and stock prices.  And that should attract a whole new group of investors.  But how do you make money in energy stocks if you don’t have time to do hours of research?

Great question, and here’s the answer–I’ve put together 6 short videos, all under 2 minutes in length, that explain the basics of the energy market to beginning investors.  I sat down with host Hannah Bernard of MarketOneMedia, and we talked about everything under the sun on energy.  Her team of post-production gurus crafted a few short clips that capture the essence of what I was trying to say.

In less than 15 minutes, you can get the trends, the context and the main news in energy for 2018.  I’ll be doing this again, so sign up my YouTube channel when you watch a video.

The NatGas Story of the Year in 2018 (100 seconds)

The Two Big Factors in the Global Oil Market in the Next 12 Months (hint–they’re both bullish; 90 second video)

The Four Key Factors In Buying Oil Stocks–with Special Emphasis on #1 (75 seconds)

The #1 Thing Investors Miss When Reviewing Oil Stocks (60 seconds)

How The Oil Market Has Changed in the Last Decade (75 seconds)

The Two Big Differences Between Canadian Oil Stocks and US Oil Stocks (75 seconds)

Those 6 videos are a great start for investors.  If you want help making money in energy, try a risk-free subscription to my independent research service by clicking HERE.

Enjoy your weekend,

Keith

It has only been two weeks since the OPEC/non-OPEC meeting and the deal they reached is already outdated.  If you blinked you would have missed it.

What has happened is very bullish for oil prices.

In case you did miss it…..the agreement that OPEC/non-OPEC came to on June 23^rd was to raise production and return to 100 percent compliance with previously agreed output cuts.

The cartel and friends had actually managed to produce less than what was agreed late in 2016.

What the band of merry misfits announced this June 23^rd was simply the intention to bring production up to the level that they had originally planned to reduce it to.  That makes sense right!

Coming out of the meeting Saudi Energy Minister Khalid al-Falih said OPEC and non-OPEC combined would need to increase production by 1 million barrels per day to bring it back to that originally agreed upon level.

But then a few unexpected things happened……..they always do.

Didn’t See That Coming #1 – Libya Production Down Big

If you aren’t following Dan Tsubouchi’s Stream Asset Energy Blog you should be.  In a recent post Dan has laid exactly what has transpired in since the June 23^rd OPEC/non-OPEC meeting.

The news isn’t good for global oil supplies.

The biggest impact is from Libya and that news broke on June 29.  Libya’s National Oil Company revealed that “force majeure” would have to be declared on the oil export ports of Zuetina and Hariga.

The problem with the ports is that the Libyan National Army (LNA) General Command is blocking entry into the facilities.  The impact of this is HUGE—even on a global scale—up to 800,000 barrels per day of global oil exports have been shut down.

Libya was producing 1 million barrels per day and Bloomberg reported that in early July, exports from open Libyan ports will only average 225,000 barrels per day in July—confirming the large production loss.

Didn’t See That Coming #2 – Syncrude’s Lights Get Turned Out

On June 22, news hit that there was a power outage at the massive Syncrude oil sands project.  That doesn’t sound like a big deal…..power outages get resolved quickly.

Somebody probably just needs flip a breaker back on.

Apparently this power outage is a little more complicated.  The word from Syncrude itself is that management doesn’t expect production to return until the start of August.

Murmurs from boots on the ground are saying that early August isn’t going to happen —- and that the end of August is much more realistic.

Syncrude has the capacity to produce 360,000 barrels of oil per day, roughly 10 per cent of all Canadian oil production.  This is a lot of oil production suddenly missing.

Didn’t See That Coming #3 – U.S. Production Growth Underwhelms

In his recent Stream Asset blog Tsubouchi also zeroes in on recent EIA production data which didn’t measure up to expectations.

Tsubouchi notes that official EIA data showed that the actual level of U.S. production for the month of April came in considerably lower than the original estimates for the month.

The April EIA Form 914 which is considered the “actual” for US oil production data revealed production at 10.467 million barrels per day — 110,000 barrels per day less than the initial weekly estimates that the market had been working with.

The concern here isn’t so much with the one month of actuals being lower than estimates but that the May and June estimate numbers are likely off as well (they use April production estimates as a base).

An even bigger concern for me is that the April actual production of 10.467 million barrels per day was flat from March’s 10.469 million barrels per day — and nobody was expecting that.

Then there are the emerging pipeline constraints that are expected to bog down Permian growth for the next two years.

Remember Why OPEC/Non-Opec Raised Production On June 23rd

Let’s do a quick tally……

Libya – down 800,000 barrels

Syncrude – down 350,000 barrels

U.S. Production – down 110,000 barrels

Add those three together and that is almost 1.3 million barrels per day of global oil production gone since June 23^rd.

This is more than the 1 million barrels per day that Saudi Energy Minister Khalid al-Falih said the OPEC/Non-OPEC boys would be adding in the coming months.

That is a pretty important series of events.  Over the past two weeks the world has actually lost production despite the OPEC news.

And finally let us not forget that oil prices having been rising for good reason.  Global inventories have been falling rapidly for months — even with full Iranian production.

Source: OGJ.com

The message here is pretty clear……..the risk to oil prices isn’t to the downside.  It is to the UPSIDE…….
And there is one jewel in my portfolio I have been buying to take advantage of all this bullish news.  It’s a US oil producer with incredible economics…so good I had to get management on the phone to confirm to me what I was reading in analyst reports.

I’ve explained the upside for you in simple English. Click HERE to get these bullish oil numbers working for you TODAY.

Keith Schaefer

I want to tell you about one of the most under-followed subsector in energy: US royalty trusts.

This is a very timely introduction and update, because many of them will be announcing their next distribution either Friday July 6, or early in the week of Monday July 9.  I think this could be A Huge Catalyst for these stocks.

These micro-cap companies have small production bases, and hardly trade–so institutions and analysts don’t follow them.  I REPEAT–these thinly-traded stocks, or illiquid stocks, are very risky.  They only issue four press releases a year–their quarterly financials. Small orders of buying and selling can mean big price movements. And when oil prices are dropping, stocks like these have almost no bids.

They are yield vehicles, but the way the oil price is shaping up now–high and going higher–they could provide some fantastic capital gains.

The Good News is…no, The Great News is…our subscribers have Nathan Weiss, editor of the institutional investment letter Unit Economics, as our guru on this topic.  He models them like an analyst, and gets very granular on what payout/distributions are possible at various oil prices.

Nathan often presents at our OGIB Subscriber Conferences, and he was in Calgary with us on May 30.  I am the only retail newsletter that is a client of Unit Economics. He focused a lot of his talk on royalty trusts.

Generally, these stocks trade at a 10% trailing yield.  Example–if the last four quarterly distributions add up to $1, a trust would trade at $10/share.

Many of these stocks are now trading at 17% yields…and if WTI goes to $100/barrel (unthinkable a few short months ago but now has an outside chance of happening) then these stocks are trading at a 30% yield, according to the distribution matrix Nathan’s firm has put together.

I’m not going to tell you anymore…you have to watch Nathan’s video, which is posted below.  I am long these stocks, but I want you to watch this more to understand the level of research my service provides.

We search out oft-forgotten parts of the energy market ahead of the crowd, and Nathan’s guidance in that has been very, very helpful.   Watch the video (click on Nathan’s picture, or the link below) for a full introduction to US royalty trusts, and put Friday July 6 on your calendar.

OGIB Calgary Conference Keynote Presentation: Nathan Weiss

Editors Note: My best two performing stocks this year have been Parex (PXT-TSX: PARXF-PINK) and GeoPark (GPRK-NYSE)–-both have doubled in the last seven months.  They are rapidly increasing production in Colombia.  Colombia just elected a new business-friendly President.  I’ll be releasing my next Colombian oil play to subscribers very shortly…to get a RISK-FREE copy of my report the day I publish it, click HERE.

Keith Schaefer

EDITORS NOTE:  I read A LOT of material each morning, and each week–and I’ve been doing this newsletter long enough now to know The Smart Money in the sector.  East Daley is one of those groups.  They focuse on midstream news (pipelines etc), and even though it’s institutional level detail & insight, it’s written for the common man.  One of their latest stories was so full of great information on the US natural gas market–there is a slew of production increases coming!!!–I asked their permission to reprint it–and they agreed.  To sign up for their free weekly newsletter, email insight@eastdaley.com .  Check them out at www.eastdaley.com

The Northeast: A (Natgas) Growth Story

• Much of the market still questions the ability of the Marcellus to grow significantly, however, the complex interconnections between many producers and midstream companies will require robust production growth to achieve financial goals and meet minimum volume commitments (MVCs).
• Producers such as Antero Resources have ties throughout the value chain which will cost them billions of dollars which will incentivize them to continue to grow production.
• Despite efforts to de-bottleneck the Northeast, much of the new open capacity exiting the region does not deliver gas to the premium markets in the Southeast-Gulf and instead competes with other producing areas such as the Permian, creating downside risk for regional producers.
• At the current forward strip, East Daley forecasts 7 Bcf/d growth from the Northeast through 2020, in addition to 10 Bcf/d from other producing regions, which intensifies the need for market participants to fully understand the intertwined relationship between oil, NGL and natural gas production in the U.S.

The Marcellus and Utica Shales, referred to collectively as the Northeast in this analysis, have grown a stunning 6 Bcf/d to 28 Bcf/d in the last year. Much of this growth has been driven through the completion of midstream projects like the Rover pipeline that have helped to de-bottleneck the area.  With Rover, NEXUS, and Atlantic Sunrise nearing completion, there will be plenty of pipeline space out of the Northeast for producers to grow as illustrated in Figure 1. From a strictly historical perspective, the de-bottleneck would make it appear that the Northeast gas market’s persistent basis discounts were over.

However, to truly understand the headwinds facing producers in the area, market participants need to take a step back and observe the entire U.S. gas market.

As apparent in Figure 2, every major basin in the U.S. is forecasted to grow gas production in the coming years. These basins combine for an additional 10 Bcf/d of growth on top of the Northeast’s 7 Bcf/d through 2020. This 17 Bcf/d of growth dwarfs forecasted demand increases of 6.3 Bcf/d, primarily driven by LNG exports. Many of the major basins in the U.S. are oil-driven and the producers there, though somewhat affected by natural gas prices, make drilling decisions based off the oil price. At $60-$70 oil prices, these basins are likely to meet or exceed current forecasts for associated gas production.

Not All Markets Are Created Equal

East Daley’s supply/demand forecast would likely be bearish for gas prices. However, not all markets in the U.S. are created equal. The Southeast-Gulf portion of the U.S., spanning from East Texas to the Atlantic Coast, has remained the premium market and accounts for 5.5 of the 6.3 Bcf/d of demand growth. Getting to this premium market is key for producers to avoid the impending oversupply in the remainder of the U.S. market.

The piece that the de-bottlenecking graph, Figure 1, fails to highlight is the amount of capacity that is open to the Gulf, which at this point and moving into the future, is and will be completely full. To accurately understand where regional markets will price, market participants must account for the supply-demand problem outside of the Southeast box. After accounting for any displacement opportunities, such as gas which previously moved north from the Southeast box, and for new capacity into the Southeast, the Northeast still needs to find a home for 1.3 Bcf/d of gas.

In addition, associated gas growth from areas like the Permian, Anadarko, Denver-Julesburg, and Bakken will be largely trapped outside of the Southeast until new pipelines come online near the end of 2019. At its peak, this associated gas will account for 4.6 Bcf/d of oversupply outside of the box. The associated gas growth from the Western U.S. and the projects that move it into the premium Southeast market are shown in Figure 3.

Combined with the Northeast, this ~6 Bcf/d of excess supply will be fighting for demand markets such as Chicago and Michcon, putting severe downward pressure on prices outside of the premium area.

Northeast’s Producer Pressure

A knee-jerk reaction to the over-supply problem is to say that the Northeast will have to back-down on their growth profile. An area that is completely driven by gas prices should be more affected than any associated gas production. However, when taking a closer look at Northeast producers, a different story based on a unique set of incentives arises.

Due to the years of being constrained, producers were forced to sign up for an unprecedented amount of firm transportation agreements. These “producer push” pipeline projects were necessary to allow a healthy midstream sector to build infrastructure in the area, but now leaves the producers with extremely large take-or-pay contract commitments.

The problem is then compounded when these producers’ downstream commitments and company structures are analyzed. Producers not only supported residue gas takeaway pipelines but also signed MVC’s with processors, fractionators, NGL pipelines, and in many cases, built their own gathering infrastructure. These commitments all combine to paint a picture where Northeast producers are being forced to grow in order to stay ahead of their current and upcoming contract payments and to support other segments of their business.

A good example is Antero Resources (AR), a pure-play Marcellus producer. Antero Resources guides to 4.5 Bcf/d of production by 2020 and is a seemingly obvious example for a producer who could slow production to help with the oversupply. Antero Resources, however, has signed up for $1.1 billion per year in transportation commitments on residue and NGL pipelines and $360 million per year in processing and fractionation commitments.

In addition, they have built their own gathering system and spun-off a separate LP, Antero Midstream (AM), to operate the assets. Antero Midstream has guided to 15%/year distribution growth which will require the producer, Antero Resources, to grow in order to meet this guidance. These relationships are shown combined in Figure 4, which starts to build a strong case as to why Northeast producers, like Antero resources, are highly incentivized to continue to produce and put up a fight in the U.S. market.

This issue does not stop with Antero Resources. Five of the top Northeast producers have signed up for a combined $3.4 billion of residue gas firm transportation alone. Many of them have downstream commitments as well and EQT also has associated gathering systems they must support. The fiveproducers’ residue gas firm transport commitments are illustrated in Figure 5.

A Light Headwind

The only piece of the story that can restrict the massive growth in the U.S. is a cross-commodity story. Following all commodities is essential to accurately forecast growth and understand market risk. In the Northeast, the story does not end at the gas:  it ends in the NGL market.

And, in the Permian, the story surrounds crude oil as a risk to gas growth.

Mariner East 2 (ME2), a 270 Mbbl/d NGL pipeline that has been planned by ETP (formerly Sunoco) is the key piece needed to increase production in the Northeast. Many of the largest growing producers in the Northeast have some, or all, of their production in wet areas of the Marcellus/Utica. Shown in Figure 6, ME2 is the takeaway pipeline for many of the fractionators in the area.

Without it, most of the NGLs are being railed/trucked away, but even these transportation methods are reaching critical throughput levels and cannot sustain the continued growth. Originally estimated to be in service in 2016, the ME2 pipeline has experienced regulatory hurdles that have prevented its completion. Once completed, it will be able to support 6.7 Bcf/d of associated wet gas growth allowing producers in wet areas to continue their aggressive growth profiles.

In the Permian, the only thing holding production back at current oil prices is the lack of crude oil takeaway. Though some crude can be taken away via truck and rail, the Permian is reaching a critical mass of volume where production will need to be curtailed. This curtailment could slow the growth of associated gas in the area until late-2019, which would help the oversupply outside of the premium market.

For more information, please contact East Daley at 303-499-5940 or email  jlange@eastdaley.com.

Remember to email them to get on their free list– insight@eastdaley.com 

Keith Schaefer

In US oil, high production growth = high valuation.  And the Permian formation in SW Texas has been growing faster than any other basin—which is why Permian stocks were investors’ favourite for the last two years.

In the Permian mania, stocks would trade at huge cash flow multiples—making a lot of investors very rich.

Yes, picking a fast-growing stock in the most profitable American shale play should make you a lot of money, when every barrel gets valued at 9x the cash flow it generates.  Nine times cash flow gives you a lot of leverage.

That multiple has come down a bit recently, but 7-9 times cash flow is still normal…see this valuation chart below:

Now–what if you could instead invest in a fast-growing oil producer that operates in the most profitable American shale play yet pay a bargain basement valuation?

Would you?  Of course you would!

Who wouldn’t?

The problem is that such companies don’t exist.  These fast growing Permian companies are priced to reflect that growth.

Whoa…hold on a minute.

Who said anything about investing in a fast growing, low valuation producer operating in the Permian?  All I said was that it operates in the most profitable American shale play……

Turn Around – You Won’t Believe
What You See Behind You

The entire oil and gas investment community is facing south looking at the Permian.

But…I think the Bakken has now overtaken the Permian as the most profitable shale oil play.  When you look where no one else is looking, you find great deals.

Hey, I get it…the last time anyone paid attention to the Bakken, it was before the oil crash when the play required $70 oil to break-even.

But Bakken economics have skyrocketed with the latest fracking improvements.  A little improvement has gone a long, long way to increasing profits

The chart below from Continental Resources (CLR:NYSE) details Bakken well rates of return by year of drilling.  I’ve shown it to you before, you really need to look at it again.

Bakken wells now make more money at $50 WTI than they used to at $80 WTI. At current oil prices these wells are generating triple digit rates of return.

The money that can be earned drilling these wells is now even better than the core of the Permian.

That means these Bakken stocks will get MUCH better valuations—Permian-style valuations—very soon.

I’ve found a company that is

1. In the heart of the Bakken
2. Will almost double production in 2018
3. Almost double again in 2019
4. Is trading for a hair over 2x YE 2019 cash flow
Let me frame that for you.  This company is growing at more than twice the rate of the fastest growing Permian producer but trading at less than one quarter of the valuation.

The investment herd loves the Permian.  It does not love the Bakken. As an investor you know that the way to really make money is by not following the herd.  You make money by thinking for yourself.

While the rest of the market remains glued to the Permian you currently have a chance to own a Bakken producer that is growing at triple digit rates and trading at an absurdly low valuation.

I’m serving this company trading at just over 2x YE 19 cash flow.

What does that mean to me?  It means there is strong potential for a 400% gain on this stock in just 18 months.  I just put $200,000 of my own money into it. (And that’s nothing…the Chairman of this Bakken producer put in $35 million of his money!)

I’ve saved a copy of my full report on this incredibly undervalued company.  To escape the investment herd and make some real money just click here to see it….

Keith Schaefer

North America is finding more oil than it can pipe or ship. Investors and the general public alike now know the story about pipeline constraints; it’s in our newspapers every day.  Right now, the Permian formation in west Texas has it, and Western Canada has it.  The Bakken play in North Dakota had it in 2012.  (And the Marcellus natgas formation in Pennsylvania has had it for almost 10 years!)

There’s a unique solution–or at least a partial solution–to Canada’s problem, and that is: upgrading Canadian heavy oil.

Below, I’ll introduce you to three innovative minds who are working on this problem.  But first, let me give you the set-up on why this is needed:

Right now for Western Canada, the numbers are–pipeline capacity out is about 3.8 million barrels.  Exports (production less Canadian refining) are expected to average 4 million barrels a day in 2018, rising to 4.3 million barrels per day in 2019.

That oil has got to get out of the country and if its not going by pipeline, it must go by rail.

It’s the story of two options.  Which is true for now.  But partial upgrading of Canadian heavy oil would be a third way, and it’s gaining some traction.

The Role of Diluent

Pipelines ship about 2 million bbl/d of bitumen to the south.  But the pipeline capacity needed to ship those volumes is closer to 2.6 million bbl/d.

Why so much more?  Because bitumen does not flow on its own.  To get bitumen to flow you must mix it with lighter oil, called diluent. (Easy to remember as it sounds like ‘diluted’ which is what diluent does.)  About half of the diluent used is ‘condensate’ from western Canadian natgas producers (it’s the only product they’re getting any real cash flow from.)

It takes a mix of roughly 30% diluent / 70% bitumen to get bitumen to flow in a pipeline.

Adding the diluent serves no purpose apart from getting the bitumen moving.  In fact, it’s a nuisance for on the other end.  The refiner has to strip it out and in some cases send it right back up a pipeline to Western Canada!

Reducing diluent requirements would free up pipeline capacity.  While not a saviour to the industry, it is incremental capacity that would ease the transportation crunch.

Importing to Export

Western Canada actually imports diluent just so it can export it back out.

Below are Canadian brokerage firm RBC’s estimates of the blending requirements of bitumen.  Roughly 600,000 bbl/d of diluent were blended in 2017.  This will increase to 675,000 bbl/d by 2021 as oil sands production grows.

Considering that the shortfall in capacity is about 750,000 bbl/d by 2021, in theory, if you could get rid of all the diluent requirements you’d be nearly balanced.

Its not quite that simple however.  “Indigenous” condensate (condensate produced in Alberta), amounted to over 300,000 bbl/d in 2017.

Even if you removed the need for diluent, you’d still need pipelines to move that condensate to market.

Condensate producers would also be seeing a much lower price.

But reducing the reliance on imported diluent would still free up 220,000 bbl/d of pipeline capacity, which is a worthy goal.

Diluent Is Expensive

Diluent is an added cost to producers.  They pay a premium for diluent in Alberta and then are forced to sell it at a discount when its removed at the refinery.

The net cost of adding diluent is between $6-$8 per barrel for the oil.  On top of that its another $7 per barrel in transportation costs, fees and levies.

Partial Upgrading Not Full Upgrading

So how do you reduce the reliance on diluent?  You need to upgrade the oil in Western Canada.

But full upgrading of bitumen is costly.  The recently built Sturgeon upgrader/refinery came in at over $9 billion.  Before it was cancelled Suncor’s Voyageur upgrader was slated at $21 billion!

Partial upgrading has more promise.   The goal of partial upgrading is to try to upgrade the bitumen just enough to get it to flow in the pipeline.

The Alberta government, recognizing the logjam of oil, in February announced a $1-billion loan guarantee and grant program for companies willing to set up partial-upgrading facilities in the province.

Older Partial-Upgrading Process Was Too Expensive

Traditionally even partial upgrading has been too expensive.

The legacy process employs delayed coking.  This is a step in most refineries but can be used as a stand-alone process to “lighten” up the bitumen.

But a stand-alone delayed coking facility costs $60,000 per bopd (barrels of oil per day) or more.

In comparison to Sturgeon (which came in at $185,000 per bopd), or Voyageur ($85,000-$110,000 per bopd depending on the source), its favorable.  But not enough to justify building one, especially since what comes out is a lower quality oil.

THREE New Technologies Showing Some Promise

Delayed coking is expensive is because it upgrades the bitumen too much.  The product is better than pipeline specs.

Others have been trying to modify the process to bring down costs.

Meg Energy (MEG-TSX) was one of the first.  They came up with better product called HI-Q (less naphtha and residuals, more gasoil and diesel) but it still wasn’t cheap enough.  Capital costs were $30,000 per bbl/d.

The company hasn’t said much about HI-Q in the last couple of years.

But while Meg seems to have stepped back, others are still forging ahead.

There are more companies than I have room to talk about.   I’m going to mention three.

1. Fractal Systems: JetShear

Fractal Systems is a private company.  They are farthest ahead with their JetShear technology.

The JetShear process heats the bitumen and brings it to a high pressure before pumping it through a proprietary nozzle.

The sudden change in pressure through the nozzle results in cavitation.  Cavitation re-arranges the asphaltene molecules, separating them into structures that have lower viscosity (higher viscosity=flows like molasses, lower viscosity=flows like water) and lower bulk density.

The result is a 19° API oil with far lower viscosity, with the added benefits of lower acid and sulphur content.

The process doesn’t quite get the bitumen to spec, but it reduces diluent requirements by 42% to 60%.

A few years back Fractal landed a big oil sands player to test the technology in Cenovus (CVE-NYSE/TSX).
Since 2014 they have operated a 1,000-bopd pilot plant near Provost Alberta.  In February Fractal announced that the process was ready for commercial production.

2. FluidOil Viscositor Heay-to-light

FluidOil is another small private company, though it’s trying to go public via Dawson Gold (DYU-TSXv).   Their technology is called Viscositor Heay-to-light (VHTL), which is a combination of their proprietary Viscositor technology and the Heavy-To-Light (HTL) they acquired with the energy assets of Robert Friedland’s Ivanhoe Energy.

VHTL is probably the closest to traditional upgrading in that it relies on a high temperature cracking and basic hydrogenation with no particular catalysts.

What makes VHTL unique is its scale.  Its intended to be implemented at the well site where heat from coking can be recycled into steam and reduce natural gas requirements.

The VHTL process produces 21° API oil though the company says this can be raised to 29° API oil.  It also removes some sulphur from the fluid.  No diluent is required.

FluidOil has a relationship with a major Canadian oil sands producer (there is no other kind anymore! Everybody else has left!) to move the process forward.  They are also working with Pemex on a project upgrading Mexican heavy crude.

3. Sherritt International Autoclaves

Sherritt (S-TSX) is a nickel miner, which makes it an unlikely participant in the race for better upgrading technologies.

However Sherritt’s history also includes a foray into coal gasification.  That combined with the re-use of their nickel smelting pressure chambers (called autoclaves) have created a unique method of upgrading.

The process combines bitumen with hydrogen and another proprietary catalyst within the autoclave.  The pressure, hydrogen and catalyst do the work of lightening up the bitumen.

The bitumen is refined to 24° API.  This is above pipeline specs, so they dilute the oil further with raw bitumen.

The process is really early stage.  But Sherritt appears serious about moving forward. The company made it a key presentation in their recent Analyst Day.

Sherritt says their process is the lowest on the cost curve, as you will see in their chart below.

Capital Costs Of The New Technologies

Like I said it’s all about capital. With each process costs are coming down, at least on paper.

FluidOil says its capital costs for a 30,000 bopd VHTL unit would be in the range of $7,500-$10,000 per bopd (barrel of oil per day). If this process was used in a lower cost country, management says the cost would be 40% less.  This capital cost will reduce even further if only pipeline spec quality (lower than 29 degree API, or just to Syncrude quality) is required.

Fractal Systems says their JetShear capital costs are around $6,000 per bopd.  This is even lower, but some diluent is still required.

Sherritt has been more tight lipped about capital costs.  What they do provide (see chart below) is a breakeven WCS price comparison.  It suggests they can come in with costs below all the competitors. (I inserted where FluidOil says they would come in.)

I’m not sure how much stock to put in this comparison (pardon the pun), as their process appears to need huge scale to get costs that low–so on a per barrel basis it might be cheap, but the sheer size required says their process would need a HUGE upfront capex number.

Conclusion

Partial upgrading isn’t going to change the need for more pipeline capacity.  But it can lessen it and allow more money to stay in Western Canada.

These technologies are still in the early stages.  The opportunity exists to squeeze more costs out and create a better product.

But there are also still questions about product quality and equipment life cycles.

What we do know is with the upcoming logjam of heavy oil there is room for new ideas.

Apart from Sherritt, there is no public company that allows you to play the sector.  But I’ll be following the developments closely and be on the look out for announcements of commercial facilities being developed.

EDITORS NOTE: One of the most important factors in buying oil stocks is…how much stock does management own?  Are they fully aligned with shareholders?  The Chairman of my most recent stock pick put more than $35 million of his own hard cash into his company: that’s commitment.  I think he’ll make (an even bigger) fortune, because I really like his play and his strategy.  Join the multi-millionaire Chairman and me and get the name and stock symbol of my latest pick by clicking HERE.

Something happened while everyone in the oil business was getting all hot and bothered about the Permian Basin.

Bakken operators made a game-changing breakthrough in their completion methodology.

The chart below from Continental Resources (CLR-NYSE) tells you everything that you need to know.

The blue line represents rates of return at various oil prices using 2018 completion methods.

They are spectacular…………..

Please appreciate that this is not a minor breakthrough.  These completion improvements are nothing short of game-changing for Bakken operators.

Consider the rate of return on Bakken wells at $65 per barrel oil by year of completion methodology vintage:

2011 – 10 percent rate of return

2014 – 20 percent rate of return

2015 – 40 percent rate of return

2017 – 70 percent rate of return

2018 – 140 percent rate of return!!!

Bakken operators can now make good rates of return with oil prices as low as $50 per barrel. At current oil prices these Bakken wells gush cash flow and payback the capital invested in months……which is the key to success.

The value of Bakken land has increased exponentially as a result of this completion breakthrough.

These Bakken drilling locations are now every bit as valuable as drilling locations in the core of the Midland or Delaware Basins.

Except they are better aren’t they?

Because while Permian operators have overwhelmed takeaway capacity and are facing discounted Midland oil pricing, Bakken producers have no such problems.

Yet companies in the Bakken are valued at a significant discount to their Permian competitors.

Which makes the Bakken the place that investors should be looking to in 2018.

The Cheapest, Fastest Growing Oil Producer I’ve Ever Seen

I haven’t just told my subscribers that I’m bullish on the Bakken in 2018.

I’ve told them that I’ve never been more bullish on one particular company…..a very small Bakken pure-play operator.

In fact I’ve never seen such an incredibly obvious bargain.

The only reason that such a bargain exists is because hardly anyone has even heard of this off-the-radar operator.

The story here is so simple that you don’t need to know anything about this company beyond three basic facts.

Basic Fact #1 – This Bakken pure-play will jump production from 2,000 barrels per day to near 20,000 barrels per day in just two years.  Yes that means production is going up almost tenfold.

Basic Fact #2 – All of this growth will be financed by internally generated cash flows—no new equity or debt.  Can you ever recall a company that could grow this fast without leveraging up?

Basic Fact #3 – This company trades at a measly 2 TIMES Year-End 2019 CASH FLOW…….
Nothing more needs to be said.

All of those facts can be verified in my comprehensive subscriber report on this company.  Those facts speak for themselves.

This is the cheapest, fastest growing oil producer that I have ever seen.

Over the next couple of years I expect it to be one of the best investments that I have ever made as well.

Click here to read our free report.

The junior lithium sector got a new valuation benchmark at the end of May when Aussie-listed Galaxy Resources (GXY-ASX) sold some grassroots lithium assets in northern Argentina to POSCO, a Korean conglomerate.

The ground was in the northern basin at Sal de Vida, in northern Argentina, and Galaxy received US$280 million cash. The package consists of a JORC-compliant total resource of 2.54 million tonnes of Lithium Carbonate Equivalent (LCE), of which 1.58mt was in the measured and indicated (M&I) categories (JORC is roughly the Aussie equivalent of a Canadian 43-101 report).

M&I stage assets have had a lot of work done on them; these are not pie-in-the-sky initial resource numbers. The Market takes this stage of resource development a lot more seriously.

That’s a valuation of roughly US$177 EV/t of M&I LCE, where EV=Enterprise Value (market cap + debt).  On a total resource basis, it works out to US$110/t, or at a simple exchange rate of $1.30, about CAD$148/t. Here’s a table that shows how several leading lithium juniors line up against this valuation.

Of those that have at least an initial resource, Advantage Lithium (AAL-TSXv) is among the cheapest.  This table also shows how valuations move up as the resource becomes more secure—with a PEA, or Preliminary Economic Assessment, and then again more value once construction is underway.

The two most recent transactions in the lithium space were done at the resource stage, (see bottom two rows in chart), and were at valuations almost double what the current crop of juniors is trading for.  Despite the Market’s concern of an increase in lithium supply in early 2019–which has kept lithium stocks down–the industry continues to buy up assets at high valuations.

All of this makes me think the EV Trade–Electric Vehicles–for junior lithium and cobalt stocks will see much better days this year.

The Street was surprised by the high value of this transaction.  This asset was not one of Galaxy’s core assets.

Australian brokerage firm Hartleys said in their note just after the transaction was announced—”On face value, the deal appears tremendous, as GXY appears to have sold an asset for significant value for which we had not valued. In particular, the deal is equivalent to ~30% of GXY market cap for an asset we had attributed  minimal value for, which bulls point to as evidence for the strong demand for high quality lithium assets.”

To me this is a very telling comment—Hartleys is saying that to the finance community, this ground was essentially worthless, but it was worth US$280 million to the industry players.

That should speak volumes to lithium investors.  The industry thinks this is a bull market and is willing to pay Big Money for what appears to be Tier II assets.

Another Aussie firm, Bell Potter, said POSCO paid such a high price because “of what we understand is a more unconventional brine project that incorporates its own proprietary technology rather than the usual brine evaporation process being adopted by GXY for SDV.” SDV being the Sal de Vida asset.  Chemistry is important in sourcing lithium.

Let’s go back to Advantage Lithium for a moment.  Their drilling has shown they have a very similar asset as LAC, which is Cauchari in the same Lithium Triangle. Advantage and partner Orocobre have the ground on both sides of LAC’s Cauchari-Olaroz project…which is in the construction phase.

Advantage’s drill results show they have similar grade, arguably a fraction lower.

And they have the biggest catalyst in their history coming in just one month’s time: their PEA, or Preliminary Economic Assessment.  As you can see from the “comp” (for comparables) chart above, that indicates the Market is willing to bump a company’s value when that happens. It works out to a 40% bump for Advantage with the PEA in hand, and nearly a double in valuation once construction starts.

With PEA in hand, management will go out to the industry—from the upstream players like SQM, FMC, Albemarle, Orocobre et al—to the downstream players like POSCO/Tesla/Ganfeng/Toyota—the list goes on (these four are just the most recent downstream players to do deals with small upstream lithium manufacturers…just to secure supply) to secure construction financing.

Management is quite hopeful that will result in non-dilutive capital.  The goal is to get the industry supply chain to pay up just to secure supply–in an area with great infrastructure already, and supportive governments.

These latest lithium transactions–one just over a week ago–helps the Market value the many junior lithium stocks.  The industry is clearly more bullish than investors right now.  But with the lowest valuation in its peer group at the moment, a clear near-term catalyst in place and a large resource, Advantage could be the first to move up the ladder and see gains for investors.

Keith Schaefer